The present invention is directed to a method and apparatus for testing and producing hydrocarbon formations found in deep (over 300 feet) offshore waters, particularly to a method and deepwater system for economically producing relatively small deep water hydrocarbon reserves which currently are not economical to produce utilizing conventional technology.
Commerical exploration for oil and gas deposits in U.S. domestic waters, principally the Gulf of Mexico, is moving to significantly deeper waters (over 300 feet) as shallow water reserves are being depleted. Deep water exploration is usually undertaken only by major oil companies, due to its very high cost. The major oil companies must discover very large oil and gas fields with large reserves to justify the large capital expenditure needed to establish commercial production. The value of these reserves is further discounted by the long time required to begin production using current technology. As a result, many smaller or "lower tier" offshore fields are deemed to be uneconomical to produce. The economics of these deepwater small fields can be significantly enhanced by improving and lowering the cost of methods and apparatus to produce hydrocarbons from them.
In water depths up to about 300 feet, in regions where other oil and gas production operations have been established, successful exploration wells drilled by jack-up drilling units are routinely completed and produced. Such completion is often economically attractive because bottom founded structures can be installed to support the surface-piercing conductor pipe left by the jack-up drilling unit. Moreover, in a region where production operations have already been established, available pipeline capacities are relatively close, making pipeline hook-ups economically viable.
Significant hydrocarbon discoveries in water depths over about 300 feet are typically exploited by means of centralized drilling and production operations that achieve economies of scale. These central facilities are costly and typically require one to five years to plan and construct. To economically justify such central facilities, sufficient producible reserves must be proven prior to committing to construction of a central facility. Depending on geological complexity, the presence of commerically exploitable reserves in water depths of 300 feet or more is verified by a program of drilling and testing a number of expendable exploration and delineation wells, typically 4 to 12 wells. The total period of time from drilling a successful exploration well to first production from the central drilling and producing platform typically ranges from two to ten years.
A complete definition of the reservoir and its producing characteristics is not available until the reservoir is produced for an extended period of time, typically one or more years. However, it is necessary to design and construct the producing facility several years before the producing characteristics of the reservoir are precisely defined. This often results in facilities with either excess or insufficient allowance for the number of wells required to efficiently produce the reservoir and excess or insufficient plant capacity at an offshore location where modifications are costly.
Early production and testing systems have been used in the past by converting Mobil Offshore Drilling Units ("MODU's"). A drilling unit is overkill for early production of less prolific wells and when the market tightens, such conversions may not be economical. Similarly, converted tanker early production systems, heretofore used because they were plentiful and cheap, can also be uneconomic for less prolific wells. The system of the present disclosure efficiently and economically supports a production operation, whereas a MODU is intended for drilling and a tanker system for transportation of hydrocarbons.
As noted in U.S. Pat. No. 4,556,340 (Morton), floating hydrocarbon production facilities have been utilized for development of marginally economic discoveries, early production and extended reservoir testing. Floating hydrocarbon production facilities also offer the advantage of being easily moved to another field for additional production work and may be used to obtain early production prior to construction of permanent, bottom founded structures. Floating production facilities have heretofore been used to produce marginal subsea reservoirs which could not otherwise be economically produced. In the aforementioned U.S. Pat. No. 4,556,340, production from a subsea wellhead to a floating production facility is realized by the use of a substantially neutrally buoyant flexible production riser which includes biasing means for shaping the riser in an oriented broad arc. The broad arc configuration permits the use of wire line well service tools through the riser system.
In U.S. Pat. No. 4,784,529 (Hunter) a mooring apparatus and method for securely mooring a floating tension leg platform to an anchoring base template is disclosed. The method includes locating a plurality of anchoring means on the sea bed, the anchoring means being adapted for receipt of a mooring through a side entry opening in the anchoring means. A semi-submersible floating structure is stationed above the anchoring means for connection thereto by the mooring tendons.
An FPS (Floating Production System) consists of semisubmersible floater, riser, catenary mooring system, subsea system, export pipelines, and production facilities. Significant system elements of an FPS do not materially reduce in size and cost with a reduction in number of wells or throughput. Consequently, there are limitations on how well an FPS can adapt to the economic constraints imposed by marginal fields or reservoir testing situations. The cost of the semisubmersible vessel (conversion or newbuild) and deepwater mooring system alone would be prohibitive for many of these applications.
Note that the semisubmersible configuration was developed for drilling applications. Here a large amount of payload must be supported with low free-floating motions. In marginal field applications neither requirement is important. In the present invention, only small payloads are required and these can be supported on a small deck which can be supported by a centrally located single surface-piercing column, rather than four corner located surface-piercing columns. Low freefloating motions are not required because a permanent vertical tension mooring will restrain vertical motions. As the need for large waterplane area is reduced, the structure in the wave zone can become more transparent, reducing environmental load and cost.
A TLP (Tension Leg Platform) consists of a four column semisubmersible floater, multiple vertical tendons on each corner, tendon anchors, and well risers. A single leg TLP has four columns and a single tendon/well. The TLP deck is supported by four columns that pierce the water plane. TLP's typically bring well(s) to the surface for completion.
As the TLP size is reduced, and the distance between corners diminishes, yaw motions increase and lead to interference between well risers. They twist around each other thereby creating a potential safety hazard with well risers. In the case of a single leg TLP, a catenary mooring is required to prevent large twisting displacements. The deepwater catenary mooring is a substantial additional cost element.
There are limitations on the extent to which a TLP can be reduced in size and cost. No matter how small the TLP's payload, it must contain enough buoyancy to keep sufficient pre-tension on tendons so that tendons never go slack as a wave trough passes. A slack tendon can snap to very high tension loads that cause high fatigue damage or overstress.
A further restriction in shrinking a TLP is the fact that during tow and installation, the TLP's stability depends on water plane area. This limits how close together the columns can be spaced. After the TLP's tendons are in place, the tendon tension stabilizes the TLP and it need not be stable in the free floating condition. The system of the present disclosure is designed for a stable tow with only a single column piercing the water plane. A conventional TLP has at least four columns that pass through the water surface and attract environmental load. This is four times as much column wind area and load as the system configuration of the present disclosure.